In the recovery of hydrocarbons from subterranean reservoirs, the use of primary production techniques (i.e., use of only the initial formation energy to recover the crude oil), followed by the secondary technique of waterflooding, recovers only about 60 to 70% of the original oil present in the formation. Gas well production systems are generally limited in their production due to the load of oil and water in the flowlines.
In most gas wells, water and/or condensate is produced along with gas. In mature gas wells, decreasing formation pressures and gas velocities gradually cause the wells to become “loaded” with liquids. Because of the difficulties in treating liquid-loaded wells with higher condensate cuts, operators may use a variety of methods to prevent liquid loading in marginal gas wells. These methods include: the use of intermitters; velocity strings; adding additional compressor capacity; and applying chemical foamers.
Intermitters allow for periodic gas flow interruptions that enable the formation to temporarily increase down-hole gas pressure in the reservoir during the shut-in phase. This accumulated pressure provides sufficient gas velocity to unload liquids from the well when opened. This continues until the actual gas velocities decrease below the critical velocities where loading occurs. A disadvantage of this type of production method is the loss of gas (and condensate) production during the “off” periods.
Velocity strings are inserted tubing strings that are narrower than the existing tubing (typically a wide capillary string) that enable the user to physically increase the linear velocity of the gas and, in turn, prevent liquid loading. A disadvantage of this type of production method is the possible loss of production, due to the restriction the string creates.
Added compression capacity reduces the overall wellhead pressure and thus increases the differential pressure with the down-hole pressure. This removes gas back-pressure restrictions that are conducive to liquid loading. A disadvantage of this option is the large capital expenditure required to add compressors.
A method commonly used to deliquify these wells is through the application of chemical “foamers”. However, these traditional foamers tend to be ineffective as the condensate-to-water ratio increases. During underbalanced drilling, the drilling fluid may be mixed with other materials, such as nitrogen, air, carbon dioxide, air-filled balls and other additives to control the drilling fluid density or the equivalent circulating density and to create foam in the drilling fluid to provide gas lift downhole.
The gases which are commonly employed in gas-drive methods include for example, nitrogen, carbon dioxide, methane, mixtures of methane with ethane, propane, butane, and higher hydrocarbon homologues. This class of gases includes both natural gas and produced gas.
Further, it has been found that recovering gas and other fluids from gas wells and pipelines using foams is different from using foams to recover oil from subterranean formations. It cannot be assumed that a composition used in one method would necessarily work in a different method.
Further, the use of certain other techniques is also known within the art. For instance, plunger lift is an artificial-lift method principally used in gas wells to unload relatively small volumes of liquid. An automated system mounted on the wellhead controls the well on an intermittent flow regime. When the well is shut-in, a plunger is dropped down the production string. When the control system opens the well for production, the plunger and a column of fluid are carried up the tubing string. The surface receiving mechanism detects the plunger when it arrives at surface and, through the control system, prepares for the next cycle.
Gas lift techniques have been used to obtain additional production when wells become loaded with fluids. Gas is injected into the production tubing to reduce the hydrostatic pressure of the fluid column. The resulting reduction in bottomhole pressure allows the reservoir liquids to enter the wellbore at a higher flow rate. The injection gas is typically conveyed down the tubing-casing annulus and enters the production train through a series of gas-lift valves. The gas-lift valve position, operating pressures and gas injection rate are determined by specific well conditions.
It would be advantageous if a new foam-forming composition were devised to give improved and more effective liquid unloading of fluids from gas wells and/or pipelines.